In developing the 200 million-barrel Northstar field some six miles offshore in the icy Beaufort Sea, BP Exploration (Alaska) Inc. placed a tall order with its engineering teams: Find a way to overcome the remote location and harsh Arctic Ocean environment and to wedge traditionally larger infrastructure into the tight quarters of a five-acre development island.

“Developing the field presented a whole series of technical issues and logistical challenges,” said John Denis, resource manager for BP’s North Slope fields other than Prudhoe Bay. “When you’re on an island like that, you quickly get concerned about space and size because you’re in very tight quarters. Things like well spacing and systems to control wells become very important.”

Also, “you couldn’t have 24/7 access,” Denis said. “You can’t just drive up to the field.”

Innovators at BP took on these challenges and nearly a decade and 115 million barrels of crude production later, the company considers the field a triumph.

Northstar hit its milestone of 100 million barrels of oil production in mid-2006, nine months ahead of schedule. The field came on stream Oct. 31, 2001.

Still, victory came with successful application of several unusual technologies.

“Northstar was the first true island in the Arctic for oil development,” Denis said.

The five-acre pad erected on Seal Island was so far from shore it wasn’t possible to connect to land with a causeway like BP did when it built the Endicott island complex just offshore in the 1980s.

Buried, but safe pipelines?

“So we were faced with having to connect the island back to the mainland with a pipeline,” Denis said.

Building a buried pipeline under the ocean to transport crude from the island to shore was a considerable challenge, but further complicating matters was the fact that the pipeline route lay hidden from view beneath the Arctic icepack most of the year.

“So very quickly, we had all the issues associated with that,” Denis said.

How could BP bury a pipeline offshore in an area covered with ice three-quarters of the year? How could the company protect such a line from the scouring action of Arctic ice? How could it ensure that the pipeline could be monitored in such an environmentally sensitive part of the world, while providing reliable leak protection and assurances to governments, agencies, Alaska Natives and the company itself?

With all these questions looming, BP’s engineers went in search of answers.

“We went looking for the best technology that would work,” said BP spokesman Steve Rinehart. “We needed some different tools, the best ones we could find to make this work.”

Much of the Northstar pipeline plan soon fell into place, but the technology that provided the critical component was the “LEOS” leak detection system developed by Siemens Germany, Denis said.

Given that Northstar was a remote field, environmental groups, Alaska Natives, whalers and others were very concerned that BP could ensure there would be no offshore leaks or spills from pipelines, he said.

Northstar is a very pressure-sensitive reservoir. Keeping the field’s pressure as high as possible is key to its operation. BP realized that shipping gas to the island from Prudhoe Bay and injecting it down hole, along with water and gas produced on the island, would be a smart move. So another subsea pipeline was needed to carry natural gas to the island for an enhanced oil recovery program, Denis explained.

Add LEOS, and BP suddenly had three pipelines to bury instead of one.

“The LEOS is an oxygen-filled pipe that is designed to be adjacent to the oil and gas pipelines,” Denis said. “Should a leak develop (in the oil or gas lines), those hydrocarbon fluids will seep a gas signature into the LEOS pipe. Every day, the oxygen is sucked out of that pipe and funneled across a gas chromatograph on the island. They have a little marker signal they put in onshore and when that marker signal hits, they know they have pulled all of the oxygen from the pipe.”

LEOS is designed to detect leaks as small as one barrel per day and to pinpoint the location to within a few feet.

“If there were a leak, you would see a hydrocarbon or other type of signature come across the gas chromatograph, and you can actually estimate its location by the time it registered relative to the start and end of that sweep,” Denis said.

In tests, the system successfully detected a simulated leak of one liter six miles away from Northstar Island.

“Think about it. We’ve bundled these pipelines and sealed them all up together as a group, and it’s kind of like a giant straw running down the middle of them,” said BP spokesman Steve Rinehart.

“That straw is permeable, so if anything is leaking out of the oil or gas lines, those hydrocarbons will permeate the straw. As we monitor what’s in the straw, we can tell if there are any leaks along the pipe,” said Denis.

It was the first time in Alaska that LEOS was used, and it was fairly new technology at the time, he said.

BP is now using a variation of LEOS in a new transit line the company is building to replace corroded sections of pipeline in the Prudhoe Bay field. The company added it to three miles of the transit line built this winter to Pump Station 1.

“We’re going to do a trial of the LEOS on that three-mile section. It holds out the opportunity to detect a very, very small leak,” Rinehart said.

Intelligent wells pass test

Northstar also claims the distinction of being the first North Slope field to use “smart wells.”

This innovation enabled engineers to install sensors down hole that collect data and track well and reservoir performance continuously.

“We knew we had to be able to respond very quickly to changes. And that wasn’t really being done in the industry,” Denis said.

“From a pressure point of view, we had done some work on locating technologies,” said John Garing, BP’s production team leader at Northstar. “We identified that we would be the first on the North Slope to go after fiber-optic sensors and put them down hole just above the reservoir in each well to measure pressure and temperature continuously and wire it back into our control plant, with the data available all the way down here in Anchorage.”

Previously, operators had to physically open the well bore and put tools down hole every time they wished to collect the data.

The idea was to obtain continuous data so engineers could get pressure readings as needed. In addition, “it minimized the number of times that crews had to enter the well bore with wire-line or e-line to gather equivalent data,” he said.

“There were cost savings and the advantage of not having to have the equipment operating on the wells as often, plus the opportunity to have all that data,” Garing said.

Though Northstar’s use of the fiber-optic technology wasn’t a global first, it was fairly early in the evolution of smart wells, he added.

Rig system made for walking

Another innovation at Northstar was a custom-built moving system that allows a drilling rig to walk up and down the row of wells on the island. The rig-moving system called the Columbia Moving System is a set of hydraulically driven pads that can pick up the drill rig and move it forward like a big foot.

“It can walk its way with different components of the rig, a few inches at a time, in either direction along the well row. It’s very effective with our limited spacing, going up and down the well row,” Garing said.

“It may be a few years before its time,” said Rinehart, “but it’s like the Star Wars walker.”

Though BP may be considering building one like it for use elsewhere, Garing said no other drilling rig in Alaska currently uses such a system.

Overall, BP has taken technological lessons learned at Northstar and used them to develop and enhance its operations at other fields around the world.

A team of engineers working to develop the new 120 million-barrel Liberty field, for example, is currently spending time at Northstar, studying the performance of that field’s wells.

Adds Denis: “Northstar is a huge success. BP saw all the challenges up front and met them.”